This invention relates to a process for hydraulically fracturing oil and gas wells utilizing coiled tubing, and particularly to such a process in which the oil and gas wells have multiple production or pay zones.
Hydraulic fracturing is a term that has been applied to a variety of methods used to stimulate the production of fluids such as oil, natural gas, brines, etc., from subterranean formations. In hydraulic fracturing, a fracturing fluid is injected through a wellbore and against the face of the formation at a pressure and flow rate at least sufficient to overcome the minimum principal stress in the reservoir and extend a fracture(s) into the formation. The fracturing fluid usually carries a proppant such as 20-40 mesh sand, bauxite, glass beads, etc., suspended in the fracturing fluid and transported into a fracture. The proppant then keeps the formation from closing back down upon itself when the pressure is released. The proppant filled fractures provide permeable channels through which the formation fluids can flow to the wellbore and thereafter be withdrawn.
Hydraulic fracturing has been used for many years as a stimulation technique and extensive work has been done to some problems present at each stage of the process. For example, a fracturing fluid is often exposed to high temperatures and/or high pump rates and shear which can cause the fluids to degrade and to prematurely xe2x80x9cdropxe2x80x9d the proppant before the fracturing operation is completed. Considerable effort has, therefore, been spent trying to design fluids that will satisfactorily meet these rigorous conditions.
High permeability formations such as those having permeabilities in excess of 50 millidarcy and particularly in excess of 200 millidarcy, present special challenges, especially when the reservoir temperature is above about 400xc2x0 F. In these situations, the amount of fluid lost to the formation can be very high, resulting in increased damage and decreased fracture length. Further, the difference in permeability between the formation and the fracture is less than that realized in less permeable formations. Improved fracture cleanup is therefore necessary in order to maximize well productivity.
A wide variety of fluids has been developed, but most of the fracturing fluids used today are aqueous based liquids which have been engineered for use in low permeability formations and are generally not well suited for use in higher permeability formations.
It has been common heretofore for the hydraulic fracturing of old oil and gas wells to utilize a workover rig and wireline for setting a packer and bridge plug combination about jointed tubing for isolation of each production zone for hydraulic fracturing. Such a fracturing operation is time consuming. For example, in a gas well with four production zones, the completions involving a fracturing and workover program may take about ten to fifteen days. If hydraulic fracturing is provided individually with a workover rig for each production zone in a multiple zone well, multiple trips to the well for perforating and multiple trips to the well for hydraulic fracturing are required. Obviously, substantial time and expense are involved with such a process utilizing a workover rig or other isolation methods.
However, prior. art processes have been utilized heretofore in which coiled tubing without a workover rig has been used for fracturing a gas reservoir. Upper and lower mechanical packers were utilized on upper and lower sides of the production zones. The setting and release of the mechanical packers were required for each pay zone. For example, U.S. Pat. No. 5,427,177 dated Jun. 27, 1995 shows the utilization of coiled tubing particularly for the completion of lateral wells and multilateral wells. A re-entry tool on coiled tubing has a plurality of inflatable casing packers thereon to block the annulus and permit various operations such as fracturing or acidizing.
It is an object of this invention to provide a process for hydraulically fracturing oil and gas wells having multiple pay zones utilizing a coiled tubing string and fracturing the desired pay zones in a single pass of the coiled tubing string.
Another object of the invention is to provide such a process in which the multiple pay zones are perforated prior to the hydraulic fracturing of the pay zones.
A further object of the invention is to provide such a process for fracturing a multizone well with coiled tubing in which a fracturing fluid is utilized which has a low friction for minimizing the fluid pressure within the coiled tubing during the fracturing process.
Another object of the invention is to provide a process for fracturing a multizone well with coiled tubing in which each selected pay zone is isolated separately in a minimum of time while utilizing the associated coiled tubing string with the coiled tubing movable after fracturing to another pay zone for isolation of subsequent pay zones.
This invention is directed to a process for hydraulically fracturing of oil and gas wells having multiple pay zones utilizing coiled tubing with the multiple pay zones fractured with a single pass of the coiled tubing. Each pay zone is individually isolated and fractured. Prior to fracturing the multiple pay zones are perforated in a single pass of a wireline or a coiled tubing string. The pay zones are isolated with a sand plug on a lower end of a pay zone or with swab cups.
For hydraulic fracturing of the multiple pay zones after the zones have been perforated, the lowermost or farthermost pay zone is initially hydraulically fractured, then the bottom hole assembly on the end of the coiled tubing is moved to the perforation at the next pay zone for hydraulic fracturing. This sequence continues until all of the very zones have been individually fractured and stimulated.
For isolation of each pay zone in one embodiment, a mechanical packer is positioned adjacent the upper side of the pay zone and after fracturing, a sand plug is deposited adjacent the lower side of the pay zone. Then, upon release of the mechanical packer, the coiled tubing string is raised to the next pay zone. For the lowermost pay zone, a bridge plug may sometimes be utilized without a sand plug, and for the uppermost pay zone, a wellhead hanger may sometimes be utilized adjacent the upper end of the pay zone for isolation without requiring a mechanical packer.
For isolation of each pay zone in another embodiment, swab cups may be utilized at opposed sides or ends of the pay zone. In one embodiment, a downwardly facing swab cup is positioned adjacent the upper end of the pay zone and a sand plug is provided after fracturing adjacent the lower end of the pay zone. In another embodiment, a downwardly facing swab cup is positioned adjacent the upper end of each pay zone and an upwardly facing swab cup is positioned adjacent the lower end of each pay zone for isolating each pay zone prior to hydraulic fracturing. The swab cups are normally spaced from each other a distance generally equal to the maximum thickness pay zone. Then, upon movement of the coiled tubing string to an adjacent pay zone, the swab cups do not have to be adjusted unless the thicknesses of the pay zones are widely different. Swab cups do not require setting and releasing. Thus, the swab cups and coiled tubing string can be moved quickly to subsequent pay zones. If desired, a plurality of swab cups may be provided on each side of a pay zone for isolation of the pay zone.
The fracturing material utilized with the coiled tubing of this invention provides a low friction against the coiled tubing when flowing therein to minimize the pressure in the coiled tubing which are particularly desirable at depths over about 4,500 feet. Coiled tubing normally has an external diameter of between 1 xc2xe inches and 2 xe2x85x9c inches and in some instances as great as 2 xe2x85x9e inches. Friction from the fracturing material can be reduced by reducing the rate of injection or by increasing the diameter of the coiled tubing. A low injection rate is normally undesirable for placement of the proppant and for effective fracturing of the formation. Coiled tubing has operating limitations and it is necessary that fluid pressure within the coiled tubing be within the operating range of the coiled tubing. A fracturing fluid for a specific job is selected based primarily on (1) the friction, (2) the surface pressure limitation, (3) the safe operating limits of the coiled tubing, (4) the desired fracture geometry, and (5) the characteristics of the formation. The use of a fracturing fluid having a low friction permits the utilization of a smaller diameter coiled tubing in many instances, particularly at depths over 4,500 feet. For example, at formations at about 7,000 feet in depth, a low friction fluid may be used for fracturing whereas a higher friction fluid is generally limited to substantially shallower formations.
Other features and advantages will be apparent from the following specification and drawings.